DE2317674A1 - PROCESS FOR THE PRODUCTION OF SYNTHESIS GAS AND PURE FUEL - Google Patents

Description

Process for the production of synthesis gas and pure fuels

The invention resides in the integration of two process steps, namely the cracking of heavy hydrocarbon oils by means of a fluid catalyst and the catalytic steam reforming of light hydrocarbons for the production of synthesis gas and pure fuels, in particular a natural gas substitute and low-sulfur heating oils.

As a result of the serious shortage of natural gas and other pure fuels, interest is turning to other ways of producing these substances. Various methods of manufacturing natural gas substitutes light hydrocarbons are already known and some of them are being used commercially will. This in turn resulted in a shortage of light hydrocarbons for the production of natural gas substitutes.

Crude oils and heavy hydrocarbon fractions are contaminated with sulfur compounds, nitrogen compounds, organometallic compounds and carbonaceous carbon

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High molecular weight hydrogens. These contaminated fractions require treatment to remove them Impurities, and in the usual course of the finishing process they must be removed before the process steps that actually crack the heavy hydrocarbons is carried out in light hydrocarbons. A whole series of upgrading steps are usually required in order to convert the light hydrocarbons obtained that can be used to manufacture natural gas substitutes. An already proposed procedure for Production of natural gas substitutes and low-sulfur heating oil requires the use of a lot of refinement processes including hydrocracking, air separation, partial oxidation, solvent deasphalting and hydrodesulfurization (see for example the journal "Pipeline and Gas Journal", July 1972).

The aim of the invention is to provide a more effective and less expensive process flow for obtaining Propose synthesis gas and pure fuels. Another The aim of the invention is to integrate catalytic steam reforming with kafcalytisehen cracking for efficient Production of synthesis gas and clear fuels. Another object of the invention is to provide a method for the production of the highest possible amount of a raw material for catalytic steam reforming and a natural gas substitute to propose from the full crude.

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Further objects and advantageous properties emerge from the process examples according to the invention, which follow will be explained with reference to the drawing. Preferred exemplary embodiments of the invention are shown in the drawing. In detail shows:

Fig. 1 is a functional diagram showing the context

shows, in which there is a heavy oil cracking unit, the light hydrocarbons and steam generated, this being used for the production of synthesis gas in a catalytic steam reforming unit be brought to reaction,

Fig. 2, which consists of the two individual figures 2A and 2B, a functional diagram of an integrated process for the production of the highest possible yield of natural gas substitute, whereby the heavy oil cracking with the steam reforming and other process steps is combined and the process as a whole is maximized with regard to the production of natural gas substitutes, and

3 shows a functional diagram of an integrated process, according to which crude oil is separated and in process steps such as heavy oil cracking, vacuum distillation, desulfurization and natural gas replacement preparation is treated so that both natural gas substitute and low-sulfur heating oil can be obtained.

In the first preferred embodiment of the invention

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are cracking by means of a fluid catalyst and the catalytic steam reforming for the purpose of manufacture integrated by synthesis gas.

The hydrocarbon used as a starting material for the catalytic cracking unit can be a crude oil, a primary distilled petroleum or a heavy hydrocarbon fraction, which in a process step for refining petroleum such as "visbreaking", solvent deasphalting, hydrodesulfurization, delayed coking, fluid coking or from other hydrocarbon sources such as Coal or shale oil was extracted. The catalytic cracking unit contains a reaction zone and a catalyst regeneration zone with the catalyst circulating between these two zones. According to the invention, tough cracking conditions are used, with at least 65%, mostly more than -75% and particularly preferably 80 to 100% of the starting materials to be cracked being cracked to form gas, light hydrocarbons and coke residues, and the light hydrocarbons boiling in the naphthase region. The cracking unit is insofern.integriert with a steam reforming unit, behandelt'werden as these substances with hydrogen so that die.Fraktion can be forwarded from cracked naphtha and lighter materials to the catalytic steam reforming _e A further integration can be provided by producing steam in the Catalyst regeneration zone of the cracking unit and by forwarding this steam to "the catalytic steam reforming unit for use as" reaction steam. When steam reforming are reformed for everyone.

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Naphtha weight unit requires approximately 1 to 2 weight units of steam.

The catalytic steam reforming reaction is represented by an idealized reaction in the form of a formula between the normally liquid hydrocarbon normal heptane and steam to form a hydrogen-containing gaseous one Reaction product.

C ₇ H ₁₆ + 7 H ₂ O ^cat * _> 15 H ₂ + 7 CO

There are a number of side reactions so that the discharge flow of the reaction of carbon dioxide, methane, unconsumed D _a mpf and coal contains. The reaction is used to produce synthesis gas, which can be used in the production of ammonia, hydrogen, methanol, reducing gas or natural gas substitutes.

Most steam reforming catalysts contain nickel on a carrier, and they are made by sulfur compounds and quickly deactivated by carbon formed from unsaturated constituents of the starting material. According to the invention a suitable starting material for catalytic steam reforming for the production of synthesis gas, preferably natural gas substitute, by catalytic cracking of hydrocarbons and by treating the cracked substances with hydrogen obtain.

In the second preferred embodiment of the invention

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the process units are integrated with regard to the Production of the highest possible amount of natural gas substitute from source hydrocarbons, that have a wide boiling range, such as natural crude oil that contains sulfur and metals. According to this embodiment, the starting material is first distilled to produce a pure liquid Naphtha fraction, which becomes a natural gas substitute production unit is directed. At least the largest part of the primary distilled Starting materials including the returned materials are cracked into gas and light hydrocarbons, and after a subsequent hydrogenation, these substances are sent to the natural gas substitute production unit.

In the natural gas substitute production unit, the pure light hydrocarbon fraction and the fraction resulting from catalytic cracking are reformed and further treated to maximize the natural gas substitute emissions. ”In the natural gas substitute production unit, process steps such as desulfurization, steam reforming, methanation and the removal of impurities are carried out carried out. Typical processes are published in "Hydrocarbon Processing", April 1971, pages 97, 98 and 99 _O. This publication also gives details of special process steps that can also be used, such as CO ₂ and H ₂ S removal, cf. = Pages 96, 117 and 120.

In the third embodiment of the invention are the process units integrated in such a way that both natural gas substitute and low-sulfur heating oil are produced from a single raw material

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that of a hydrocarbon boiling over a wide range like a natural crude oil with sulfur and metal components. According to this embodiment the starting material is first distilled, creating a fraction of pure naphtha and lighter substances pure gas oil and atmospheric soil products are created. The fraction of pure naphtha and lighter fabrics becomes too the natural gas replacement plant. The pure gas oil is hydrodesulfurized and the atmospheric soil products are separated into two parts. Part of the soil products will be cracked and gives a raw material for the production of natural gas substitute and the other part is made by vacuum distillation and treated at least partially by catalytic hydrodesulfurization and yields fuel oil components. The various fuel oil components are then blended to form a low-sulfur fuel oil. For the different Common hydrodesulfurization processes are used to reduce the sulfur content of fractions. Suitable Hydrodesulfurization catalysts contain at least one Hydrogenation metal on a suitable carrier. Salts of metals of groups VI and VIII are preferred hydrogenation components, especially the oxides or metal sulfides of molybdenum, tungsten, cobalt, nickel and iron. Alumina, silica-alumina, Bauxite and diatomaceous earth are suitable carriers.

According to Fig. 1, a hydrocarbon fraction is by a Line 10 is introduced into a distillation column 11. This fraction can contain between 0.1 and 8 percent by weight of sulfur

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and between 1 and 1000 ppm of organometallic compounds such as vanadium and nickel compounds. Of the Asphaltene content of the fraction can range from OyI to 20 percent by volume amount to. A fraction of pure naphtha and lighter materials is withdrawn through line 12 and above heavy soil products are discharged through line 13. The pure naphtha fraction is an upper cut of the crude oil with an endpoint up to about 205 C beyond ·; however, this temperature depends in part on the properties of the raw material and partly from the catalysts and the two the catalytic steam reforming processes Conditions. This fraction contains sulfur compounds, but it is largely free of organometallic compounds and asphalt. Therefore, while according to the invention a pure naphtha and lighter fraction has a boiling point section of up to to 185 C, the fraction can also have an end point in the Range between 94 and 232 C. The heavy oil bottoms fraction is the remainder or residue of the higher boiling point Substances of crude oil. For example, 10 to 90% of the residue can consist of substances that boil above 316 ° C. the Heavy oil bottoms are put into a heavy oil cracking unit 14 initiated. The particular cracking catalyst used in the heavy oil cracking unit 14 is not critical to that present invention, preferably zeolite-type cracking catalysts are used.

The cracking conditions are controlled so that conversion occurs of the starting material of at least 65 percent by volume and preferably from 80 to 100%. Typical cracking conditions are given in Table I below.

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Table I.
Catalytic cracking process conditions

Temperature, C pressure, atü ♦ return flow rate, vol.% (FF) Catalyst / oil flow rate ratio

per room unit (weight / hour / weight)

area - 565 preferred 455 - 3.5 650 0.7 - 100 2.1 0 - ■ 15il 50 3: 1 - 1000 6: 1 0.5 200

The heavy oil cracking unit 14 preferably uses a riser reactor 15. The actual reaction zone of the cracking unit is preferably a riser 16 which is an essential feature of a riser cracking unit such as this is described and illustrated in U.S. Patent 3,607,127 (issued Sept. 21, 1971). It will be common fluids Cracking catalysts are used, such as amorphous silica-alumina or matrix type molecular sieve catalysts (Zeolite), the mean particle size of which is between about 40 and about 100 microns. Zeolite catalysts are preferred. The heavy oil bottom products are via line 13 in the lower part of the riser 16 of the Riser reactor 15 introduced and mixed with the cracking catalyst by means of steam, which introduced through line 17 will. The riser should have a length to diameter ratio in the range of 3: 1 to 30: 1. In Fig. a kinked riser is shown as it is in detail

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in U.S. Patent 3,607,127. 50 to 95% of the Cracking reaction takes place in riser 16 and the rest in the deposition zone 18 and in the scraper 19. The Cracked materials leaving the end of the kinked riser separate from the catalyst in zone 18 and rise through cyclones (not shown) to be collected there. The catalyst and the absorbed Uncracked raw materials migrate down through the separation zone to the scraper 19. The scraper is provided with suitable impact devices and a steam ring 21, which strips off the absorbed cracked matter, which then exit upwards, while the catalyst migrates downwards into the regeneration zone 22. In the regeneration zone 22 the catalyst at regeneration temperatures with a Oxygen-containing gas brought into contact, wherein the coke on the catalyst to the desired level on residual coke of the regenerated cracking catalyst is burned off. Located within the regeneration zone 22 steam coils 23 that remove heat from the catalyst. Through a line 24 water is drawn into the steam coils introduced in which large amounts of steam are generated and carried through Line 25 are discharged. Within the regeneration zone 22 one or more dip tubes 26 can be attached »The gas-containing products are in a cyclone 27 of all Separated solids, the gas as exhaust gas through the Line 28 can be withdrawn and the solids are returned through the dip tube 26. The.regenerated Catalyst is removed from the regeneration zone 22 at a settling section 29 of the riser reactor 15 is removed by means of suitable valve and bleeding devices (not shown) and again

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inserted into the riser 16 and with the steam and the Heavy oil soil products united.

The effluent from the heavy oil cracking unit 14 is taken through line 20 to a fractionator 30. the end This fractionator can contain a return fraction consisting of heavy oil withdrawn via line 31 and returned to the unit together with the heavy oil bottom products in line "13" 14 are fed. Most of the cracked effluents are withdrawn at the top through line 32 while the few soil products can be removed through line 33 and can be used as fuel for the plant.

It should be noted that the separation process in the fractionator 30 different from the usual, following one for petroleum refineries The fractionation used in typical catalytic cracking systems is completely different. The products will separated in two main fractions land not in many ways Fractions such as light hydrocarbons, gasoline, kerosene and medium distillates. This is because the process no precursors for alkylation, high-octane reforming, for household heating oils and the like.

The upper fraction is through a condenser 34 and into a Reflux drum 35 is passed to remove the gas from the liquid to separate. The liquid cracked haphtha fraction is removed from reflux drum 35 through line 36. A part of it is returned through line 37 and valve 38 to the top of fractionator 30 as a reflux stream. The liquid cracked naphtha fraction is then poured into a

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Hydrogen unit 39 introduced and there with the through a Line 40 introduced hydrogen treated to saturate the olefins and aromatics and to remove the sulfur. the Reaction conditions in the hydrogenation unit 39 are chosen so that the hydrogenated fraction of naphtha and lighter substances is suitable for catalytically steam reformed will. Suitable catalysts and conditions for this can be selected from those given below.

The gas fraction is from the reflux drum 35 through a Line 41 is removed and is available therein for three types of applications. One application is because of the gas its high hydrogen content as a component for a To use synthesis gas. On the other hand, the gas can pass through a valve 42 of a separation unit or through a suitable valve 43 and a compressor 44 in the compressed state of FIG Hydrogenation unit 39 are supplied. .

From the hydrogenation unit 39, a hydrogenated cracked fraction of naphtha and lighter substances is fed via line 45 to a catalytic steam reforming unit 46. The hydrocarbon feed to the steam catalytic reforming unit 46 can be the saturated cracked naphtha fraction alone. However, it is preferably combined with the pure naphtha from line 12, which has previously been desulfurized in a desulfurization unit 47. The product of the catalytic steam reforming unit 46 contains 50 to 80% H "and 10 to 30% CO together with smaller proportions of CO ₉ and CH, and can be cleaned in a cleaning unit 48"

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which and then apply as a suitable synthesis gas product. Such a product can be used for the production of natural gas substitutes, Ammonia, methanol or other valuable products derived from synthesis gas.

The particular embodiment of the invention of Figure 2 illustrates the maximized conversion of crude oil to natural gas substitute. A desalinated complete crude oil containing 1.71% sulfur is passed through a line 50 at a flow rate of 150 MBD introduced into a distillation column 51. A fraction of pure naphtha and lighter fabrics including propane and butane is withdrawn at the top via line 52 at a flow rate of 39 MBD. At the bottom of the still 51 is a heavy oil fraction with a flow rate of 111 MBD withdrawn via line 53. The heavy oil bottoms are fed into a heavy oil cracking unit, the total is denoted by 54. The heavy oil cracking unit 54 is preferably a riser tube reactor, indicated generally at 55 is. The cracking catalyst of reactor 55 is introduced along with steam through line 56 into riser 57, into which the heavy oil fraction is also fed. The heavy oil bottoms become catalytic in the riser 57 cracked. The cracked hydrocarbons and the cracking catalyst are separated from each other in separation zone 58 separated. Additional cracked hydrocarbons are formed in the stripping and cracking of adsorbed on the catalyst Hydrocarbons in the stripping zone 59. The cracked hydrocarbons travel through a cyclone 60

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and exit through line 61. The separated in the cyclone 60 The catalyst is returned to the scraper via a dip tube 62. In the stripping zone 59 can Baffles 63 and a steam ring 64 aid in removing the hydrocarbons absorbed on the catalyst.

The cracking catalyst flows downward into regeneration zone 65. In the regeneration zone, the catalyst is in with air Brought into contact and the charcoal adhering to it burned down to the desired extent. In the regeneration zone 65 there are also steam coils 66. Through a conduit 67 water is introduced into this, with considerable amounts of steam being formed and discharged through a line 68 will. During the burning of the coal in the regeneration zone 67, exhaust gas is passed through a cyclone 69 and through a pipe 70 discharged while the fine catalyst grit is returned through the dip tube 71 into the regenerator bed.

The effluent stream withdrawn from the heavy oil cracking unit 54 through line 61 is directed to a fractionation tower 72. From this a considerable part of the fractionation product can be discharged through line 73 via a draining unit 74 and line 75 returned and containing the sea oil bottoms are combined in the supply line 53.

A very small fraction of the heavy soil products of the Fractionator tower 72 is withdrawn through lines 76 and 77 for use as fuel for the plant or

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for the CO boiler 78. The exhaust gases in line 70 from the Regeneration zones 65 of the heavy oil cracking unit 54 are directed to the CO boiler 78 and generate steam therein through line 79 and that in the regeneration zone 65 formed and flowing through line 68 steam is admixed.

The desired naphtha gas fraction is extracted from the fractionator passed through line 80 to a gas-liquid separator 81. The liquid cracked naphtha fraction is taken from this through line 82 and passed on to a hydrogenation unit 83. The highly hydrogenated Gases are taken out from the gas-liquid separator 81 above and also introduced into the hydrogenation unit 83, to hydrogenate both the olefinic and aromatic hydrocarbons and the cracked ones Desulfurize naphtha fraction. Almost two thirds of the hydrogen required for hydrogenation is provided by the The heavy oil cracking unit produces hydrogen which is introduced through line 84. Extra hydrogen can also be added through a line 85. The hydrogenated cracked naphtha fraction becomes from the hydrogenation unit 83 removed via line 86 and fed to a steam reforming unit 87, which is part of a natural gas replacement unit represents.

39 MBD of a pure fraction of naphtha and lighter components are passed through line 52 to a desulfurization unit 88 initiated. After desulphurisation will be

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them with 121 MBD hydrogenated cracked naphthas from the Line 86 united. Part of the combined naphtha flow, e.g. 40 to 60%, is sent through line 89 containing valve 90 and into a hydrogasification unit 91 initiated. Likewise, the product from the steam reforming unit 87 becomes the hydrogasification unit 91 headed. A portion of the Ausgarigsprodukts from the steam reforming unit is removed through line 92 and for the production of hydrogen in a hydrogen plant 93 is used, the discharge of which is introduced into the hydrogenation unit 83 via line 85. The one from the hydrogen gas generator The product obtained, which contains 50 to 90% methane, is used to enrich the methane in a methanation unit 94 initiated. The product is then through a unit 95 for removing the carbon dioxide passed and thus represents a natural gas substitute with a calorific value of represents approximately 1000 kilowatt hours. This shown in FIG special embodiment, starting with a desalinated one Whole crude oil as raw material, produces 160 MBD naphtha for steam reforming and a natural gas substitute with a Output of around 22.1 million m per day.

The individual process steps in the special process shown in Fig. Natural gas substitute production shown are preferred Examples, however, there are other processes, all of which the catalytic ^ steam reforming included as an initial step and which can be used just as well. In the preferred natural gas substitute manufacturing process, the implementation of the individual process steps as follows established general conditions.

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In the process step of catalytic steam reforming, the starting material is converted into a gas with a high hydrogen content by reacting with steam. A nickel catalyst is usually used and the reaction is carried out in a fixed bed steam reforming unit. The catalyst contains nickel including elemental nickel or a nickel compound such as nickel oxide, and mixtures thereof. The catalyst is supported by a porous, heat-resistant material that can withstand high mechanical loads and is resistant to steam and high temperatures. The preferred catalyst has a second component, namely an additional alkaline compound, with alkali metal compounds including those of sodium, sithium and potassium being preferred. Using the preferred catalyst, the steam to hydrocarbon ratio can be maintained at about 1: 1 to 2: 1 parts by weight. The temperature and pressure conditions in the steam reforming unit are approximately 450 to 500 ^° C. and 30 atm. The product of this process step of catalytic steam reforming is a gas consisting of methane, hydrogen, carbon dioxide, carbon monoxide and excess water vapor. The preferred conditions and preferred catalyst for the steam reforming step are detailed in U.S. Patents 3,119,667, 3,417,029, and 3,567,411.

Hydrogasification as a process step is a modification of the catalytic steam reforming process and

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like this, it is the result of a reaction between steam and hydrocarbons using a steam reforming catalyst. This step is carried out at essentially the same working pressures, but performed at a little lower temperatures. The reaction can be similar to the catalytic Steam reforming take place in a fixed bed. Hydrogasification produces a gas with a similar composition like that of catalytic steam reforming with the exception that the methane content is higher and the steam content higher is less. Suitable working conditions for the Hydro gas if ikat ion are a pressure of about 30 atm and a Temperature from about 370 C to 450 C. A special representation a suitable hydrogasification process finds U.S. Patent 3,625,665.

In the methanation process step, gas is turned off the hydrogasification unit is cooled to condense the actual gases and most of the excess water vapor to be deposited. The gas is then reheated at substantially the same pressure, for example 30 atm to a temperature of about 300 to 350 C. The gas is introduced into a fixed bed with a nickel catalyst, where a reaction takes place that is a balanced one Mixture results, i.e. consists predominantly of methane and carbon dioxide, with small residual amounts of hydrogen and Carbon monoxide are included.

In the process step for removing the carbon dioxide, the gas coming from the methanator is about the same

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Pressure and the same temperature of about 90 g and brought into contact with an aqueous solution of potassium carbonate in a sprinkler tower. The carbon dioxide reacts with the solution to form potassium bicarbonate, removing most of the carbon dioxide from the gas will. The wet cleaned gas leaves the sprinkler tower with a content of about 1% carbon dioxide. The enriched solution is sent to a regenerator in which a lower pressure of about 2 atm and a temperature of about 110 C carbon dioxide expelled by the application of heat converting the solution back to potassium carbonate. The regenerated solution is then used again returned to the trickle tower.

According to FIG. 3, a starting material composed of hydrocarbons is fed to a distillation unit 101 via line 100. The starting material can be crude oil with 1.71% sulfur is introduced at a flow rate of 150 MBD. A naphtha fraction is at the top of the distillation unit 101 withdrawn on line 102 at a flow rate of 39 MBD. A light gas oil fraction that boiling in a range from about 185 to 350 G is removed as a minor fraction through line 103 and passed through a desulfurization unit 104 passed, so that a desulfurized light gas oil with one flow rate of 44 MBD that flows out through line 105. 67 MBD heavy oil bottoms are withdrawn through line 106. A portion of this, 43 MBD, is fed through line 107 to the heavy oil cracking unit 108. The remainder of 24 MBD is fed into a vacuum distillation unit 109. 409820/0222

In the special embodiment shown in FIG. 3, the combination of a heavy oil cracking unit with the production of a suitable naphtha fraction for a catalytic steam reforming unit makes it possible to produce not only a natural gas substitute product, but also a low-sulfur heating oil. How are the heavy oil bottom products fed into the heavy oil cracking unit converted with a degree of conversion between 80% and 100% _? whereby an effluent stream 110 is produced which flows to a fractionation unit 111. The very high degree of conversion is achieved by taking a fraction from fractionation unit 111 through line 112 and introducing it through line 107 into heavy oil cracking unit 108 together with the heavy oil bottoms. The cracked naphtha fraction is removed at the top of the fractionation unit 111 through the line 113 and introduced into a gas-liquid separation unit 114, after it has previously been passed through a condenser (not shown). The liquid cracked naphtha fraction is withdrawn through line 115 and introduced into a hydrogenation unit 116. The gas fraction from the gas-liquid separation unit 114 is rich in hydrogen and can be used in the hydrogenation unit 116 and introduced there through line 107. The sulfur is removed from the cracked naphtha fraction by hydrodesulfurization in unit 116. The hydrogen sulfide is withdrawn through line 118. In the hydrogenation unit 116 the saturation of the contained olefinic hydrocarbons and the aromatic hydrocarbons also takes place, so that a low-sulfur

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liquid hydrogenated cracked naphtha fraction is produced, which is taken through line 119 and introduced into a natural gas replacement system 120, which is a catalytic Contains steam reforming unit in which the first process step is carried out. According to today's technology would be the starting materials of a natural gas replacement plant few olefins (less than 1 to 2%) and very little sulfur (50 to 500 ppm), aromatics (less than 25%), Naphthenes (less than 40%), preferably with as much saturated hydrocarbons as possible, i.e. with 50 to 100% included. The natural gas replacement plant is shown in more detail in FIG. 2 with regard to the production of natural gas replacement and described above. The hydrogenated cracked naphtha fraction of up to 43 MBD contains 39 MBD one pure naphtha fraction in line 102, which are treated and the natural gas substitute product of this embodiment result. The steam used as a reaction component in the steam reforming unit is that in the regeneration

egg

steam unit formed through line 121 from the Heavy oil cracking unit 108 as described above is taken.

For the production of the low-sulfur heating oil a Part at the top of the. Vacuum distillation unit 109 is withdrawn through line 122 at a flow rate of 16 MBD and introduced into the desulfurization unit 123. With the upper outflow of the vacuum distillation unit 109, the bottom products of the fractionation unit 111, which through the line 124 are taken ·, combined and in the

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Hydrodesulfurization unit 123 initiated. In this unit Hydrogen sulfide is produced, which is discharged through line 125 and a sulfur recovery unit 126 is fed. The one in the naphtha hydrogenation unit Hydrogen sulfide produced 116 and withdrawn via line 118 can also be sent together to the sulfur recovery unit 126 are directed. This unit produces sulfur with an output of 190 t per day. The Claus process can be used for this purpose.

The streams of desulfurized hydrocarbon oil can then be blended. For example, the light gas oil, that was desulfurized and taken out through line 105 with the heavy gas oil that was desulfurized and taken out through line 127 was removed and combined with the bottom products of the vacuum distillation unit 109 from line 108, so that in line 129 there is a low-sulfur Fuel oil with a sulfur content of about 0.68% and an output of about 76 MBD results.

It should be noted that FIG. 3 shows three hydrodesulfurization units, denoted by the numerals 104, 116 and 123 are designated. The embodiment according to FIG. 2 discloses hydrogenations in the with the reference numerals 74, 83 and 88 designated units. In FIG. 1, the hydrogenation takes place in the unit labeled 39. The one at a certain Fraction carried out process step of the hydrogen treatment or hydrodesulfurization can take different

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fulfill ne functions, namely hydrodesulfurization, hydrodesulfurization, the saturation of olefins and Aromatics, hydrodenitration, etc. The catalyst and the reaction conditions are selected in accordance with the properties of the raw materials to be treated and those required for a fully treated product Efficiency. Temperatures in the are suitable Range between 205 G and 455 C. The pressures are in the range between 3.5 and 140 atmospheres. Are also suitable Hydrogen gas flow rates in the range between 100 and 2000 SCF / bbl. The preferred catalysts for hydrotreating contain one or more hydrogenation metals supported on a suitable carrier material. Usable are oxides or sulfides of molybdenum, tungsten, cobalt, nickel and iron, in connection with carriers such as Alumina or silica-alumina. The most preferred catalysts are cobalt molybdate on alumina and nickel molybdate on alumina. The catalyst can be in Form of a fixed bed or a fluidized bed can be used. Liquid phase or mixed phase conditions can also be used be used. It may be desirable to use fractions or parts of fractions for hydrotreatment to separate. Hydrogen-containing gases with a hydrogen content of 60 to 100% can be used, and it is an essential feature of the present invention that the hydrogen generated in the heavy oil cracking unit can be used as a source of reaction hydrogen can. A number of hydrotreating processes with varying degrees of exposure are in the journal

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"Hydrocarbon Processing," September 1972, pages 150-184.

The sulfur recovery unit designated by the reference numeral 126 can operate according to any known method for the conversion of hydrogen sulfide to sulfur, such as the Stretford method, which is described in "Hydrocarbon Processing", April 1971, page 119, or according to the modified Claus process, described in "Hydrocarbon Processing", April 1971, page 112. ■. ■■■ "."

The methods according to the exemplary embodiments thus make it possible of the invention is the conversion of hydrocarbons into pure fuels. A completely crude oil with considerable Sulfur and metal components can be processed into the desired products, such as a natural gas substitute product with a very high calorific value (for example up to 1000 kilowatt hours) and a heating oil with a Content less than 1% sulfur. The concept of heavy oil catalytic cracking according to the present invention manure is unique in that a heavy hydrocarbon is converted and treated in such a way that it can be used as a raw material for steam reforming. the Fact that metals like vanadium, nickel and iron deny Contaminating the catalyst reduces the activity and life of the high-efficiency cracking not seriously used catalyst. Of course it will

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fresh catalyst at the catalytic cracking unit, if necessary, added. The addition can take place continuously or intermittently.

The embodiments of the invention are in view

essentially self-supporting on the energy balance. The heavy oil cracking unit generates very large amounts of steam, which can be used as reaction steam in the catalytic steam reforming process. The supply of the starting product the heavy oil cracking unit can be recirculated to zero, or part of it, if desired of the cycle material can be used as fuel for the plant. The ones for saturation and desulfurization the amount of hydrogen required for the various intermediate fractions is, in the preferred exemplary embodiments, significantly less than the amount of hydrogen, those for the operation of a hydrocracking unit and connected Hydrodesulfurization units would be required.

March 28, 191
A 1916 e-Jm

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Claims (1)

Claims Iy process for the production of synthesis gas, characterized in that that a hydrocarbon as a raw material in the presence of a cracking catalyst under hard Cracking conditions, by which is meant a conversion of at least 65% of the starting material into a catalytic one Cracking zone is introduced so as to produce an effluent flow consisting of a gas fraction with a high hydrogen content and a cracked naphtha fraction that the cracked naphtha fraction is treated with hydrogen to remove the unsaturated hydrocarbons to hydrogenate, and that this treated naphtha fraction for the production of the synthesis gas in a catalytic Steam reforming unit is initiated. 2. The method according to claim 1, characterized in that the degree of conversion is between 80 and 100%. 3. The method according to claim 1, characterized in that the cracking catalyst is a zeolite catalyst. 4. The method according to claim 1, characterized in that the effluent is fractionated and a portion is returned to the catalytic cracking zone. 5. The method according to claim 1, characterized in that the highly hydrogen-containing gas fraction for treatment 409820/0222 ./. the cracked naphtha fraction is used. 6. Integrated process for the production of synthesis gas, characterized in that a hydrocarbon is used as the starting material in the presence of a cracking catalyst introducing the catalytic cracking zone of a heavy oil cracking unit to create an effluent flow consisting of from a highly hydrogenous gas fraction and a naphtha fraction that the cracking catalyst in a regeneration zone is regenerated, which steam coils in which large amounts of steam are produced and that the naphtha fraction is collected and together with the steam under steam reforming conditions in a steam reforming unit is initiated, and that from it a synthesis gas with a higher proportion of hydrogen and carbon monoxide is obtained. 7 * Integrated method according to claim 6, characterized in that that the steam generated in the steam coils makes up 50 to 100% of that in the catalytic Steam reforming represents the required steam. 8. Integrated method according to claim 6, characterized in that that the hydrocarbon used as the starting material is a heavy oil residue. 9. Integrated process for the production of natural gas replacement, characterized in that a hydrocarbon as Starting material in a catalytic cracking zone 409820/0222 ./. Heavy oil cracking unit in the presence of a liquid one Cracking the cracking catalyst at a conversion rate of 75 to 100% to create an effluent flow, consisting of a gas fraction with a high content of hydrogen and a cracked naphtha fraction that this effluent stream is treated with hydrogen for hydrogenation of olefins and aromatics and to make a stronger one saturated cracked naphtha fraction that the hydrogenated ■ - cracked naphtha fraction is steam reformed and so on Steam-reformed product is created that consists of a strong hydrogen-containing gas, and that this is enriched to the methane content in the natural gas replacement product to increase. ■ '"..- 10. Integrated method according to claim 9, characterized in that the enrichment is a blend of the steam reformed Includes product with high methane fractions. 11. Integrated method according to claim 9, characterized in that that the enrichment the procedural steps of Hydrogasification, methanation and carbon dioxide removal. 12. Integrated process for the production of natural gas substitutes from a starting material consisting of hydrocarbons, characterized in that from the hydrocarbon oil existing raw material a pure naphtha fraction and containing sulfur and metallic components 409820/0222 ' ^Jm Soil products are distilled out that the heavy oil soil products in a catalytic cracking zone of a heavy oil cracking unit in the presence of a cracking catalyst be cracked at a conversion rate of at least 65% so as to obtain an effluent flow which consists of a high hydrogen gas fraction and a cracked sewage fraction that this discharge flow is treated with hydrogen to hydrogenate the unsaturated components of the cracked sewage fraction, that the hydrogenated cracked sewage fraction blended with the pure sewage fraction and the scrap into one catalytic steam reforming unit is initiated and that the steam reformed product is enriched to to increase the methane content in the natural gas substitute product. 13. Integrated method according to claim 12, characterized in that that the heavy oil cracking unit is a riser tube reactor. 14. Integrated method according to claim 12, characterized in that that the starting material is a crude petroleum oil. 15. Integrated method according to claim 12, characterized in that that the pure naphtha fraction has a boiling point of 185 G at most. 16. Integrated process for the production of natural gas substitute and heating oil from a crude hydrocarbon oil, thereby marked ine t, a) that the crude hydrocarbon oil by distillation 409820/0222 -30- £ ό Ι 1 ΐ> / ** under atmospheric conditions into a pure naphtha fraction, a light gas oil fraction and heavy oil bottom products are separated, b) that some of the heavy oil bottom products in a catalytic en cracking zone of a heavy oil cracking unit in the presence a liquid cracking catalyst at a conversion rate of 70 to 100% one made of a high hydrogen gas and one cracked naphtha fraction to generate existing effluent stream that this treated with hydrogen and such a desulfurized, hydrogenated cracked naphtha fraction is produced, c) that the mixture of the pure naphtha fraction and the desulfurized, hydrogenated cracked naphtha fraction is steam reformed in the presence of a steam reforming catalyst and so a synthesis gas is generated that this is enriched to its methane content increase and reduce its CO and CO «share and thereby to produce a natural gas substitute product, and d) that the light oil-gas fraction and the remaining part the heavy oil bottom products are mixed together to form a heating oil. 17. Integrated method according to claim 16, characterized in that that the light oil-gas fraction before mixing is desulfurized. 409820/0222 18. Integrated method according to claim 16, characterized in that that the remainder of the heavy oil bottoms are vacuum distilled and transferred to an upper and a soil fraction is separated. 19. Integrated method according to claim 18, characterized in that that the upper fraction of the vacuum distillation is desulfurized before mixing. 20. Integrated method according to claim 16, characterized in that that the effluent stream from the heavy oil cracking unit is fractionated and that a portion goes to the catalytic Cracking zone is returned. 28th March
A 1916 e- 409820/0222